The recovery of hydrocarbons, both liquid and gaseous, from subterranean zones has frequently resulted in the simultaneous production of large quantities of water or brines. In some cases, even though substantial flows of hydrocarbons have been shown, water production is so great and water disposal costs so high, that hydrocarbon production is not economical. Such water production has in some cases been disposed of in an abandoned or dry well by separating such water from the hydrocarbons and reinjecting the separated water into such wells. Where a disposal well is not available nor near the producing well, pipelining the water product over a long distance to a disposal site can become so costly that it renders the well noncommercial. Even if a disposal well is close by, the disposal cost can still be very expensive. Therefore it is desirable to find a way to reduce or shut off the flow of water while permitting hydrocarbon production to continue.
It is well known that the production of large amounts of water from hydrocarbon producing wells is a major expense item in the overall hydrocarbon recovery cost. It is not uncommon for an oil well to produce an effluent which is 60-99% by volume water and only 1-40% by volume oil. In such situations, the major part of the pumping energy is expended in lifting water from the well, a cost which the producer would like to avoid if possible. The effluent must then be subjected to a costly separation procedure to recovery water-free hydrocarbons. The foul water separated therefrom also presents a troublesome and expensive disposal problem. Consequently, it is desirable to decrease the volume of water produced from hydrocarbon wells. It is, of course, desirable to be able to achieve this objective and at the same time not marer-ally affect the hydrocarbon recovery rate. However, where the volume of water is very high, e.g., 80 to 99% water, and only 1-20% oil, even substantial reduction in hydrocarbon production can be tolerated if water production can be substantially reduced.
One such method of reducing the flow of water has been described in U.S. Pat. No. 3,762,476 wherein a first aqueous polymer solution selected from the group consisting of polyacrylamide, a partially hydrolyzed polyacrylamide, a polysaccharide, a carboxymethylcellulose, a polyvinyl alcohol, and polystyrene sulfonate, is injected into a subterranean formation. Thereafter, a complexing ionic solution of multivalent cations and retarding anions, and which also comprises aluminum citrate, is injected into the subterranean formation. The multivalent cations are selected from the group consisting of Fe(II), Fe(III), Al(III), Ti(IV),Zn(II), Sn(IV), Ca(II), Mg(II), Cr(III), and the retarding anions are selected from the group consisting of acetate, nitrilotriacetate, tartrate, citrate, phosphate. Brine is then injected followed by a second slug of an aqueous polymer solution which can be the same or different from the first aqueous polymer solution. In any event, the complexing ionic solution of multivalent cations and retarding anions is capable of gelling both the first and second aqueous polymer solution.
Water produced from a wellbore can come from the infiltration of naturally occuring subterranean water as described above, or the water can come from injected water put into the formation in those hydrocarbon recovery processes which utilize waterflooding. U.S. Pat. No. 4,098,337 discloses a method for forming a hydroxymethylated polyacrylamide gel, in situ, to reduce the permeability of a thusly treated zone where the waterflood method of oil recovery is employed. In this case the gel was formed in situ by the injection of an aqueous polyacrylamide solution and a aqueous formaldehyde solution.
In waterflood operations it can be desirable to treat the water injector wells with a polymer gel forming solution to control and/or redirect the water flow profile. Such treatment can prevent channeling of water at the injector well and/or control or redirect the water flow through regions of varying permeability.
Although polyacrylamide-based gels can be effective in retarding water production or flow in some subterranean formations, polyacrylamide-based gels will not be stable or effective in all formations. In general, polyacrylamide-based gels will work satisfactorily in formations having a temperature below about 65.degree. C. Above about 65.degree. C., Polyacrylamide-based gels become very sensitive to hardness of the brines, especially where hardness is above about 1000 ppm. The hardness of the water becomes a more detrimental factor the higher the temperature, thus for very hot regions even low hardness levels can render many gels ineffective. Formations which have a higher temperature, hardness, or total dissolved solids content above the aforementioned ranges usually are not capable of being successfully treated with polyacrylamide-based polymers to retard the flow of water.
In many hydrocarbon producing wells temperatures of 80.degree. C. or higher are often encountered. Formation waters frequently have hardnesses which exceed 1000 ppm. It is therefore desirable to develop a gel which can be used to retard or block the flow of water in subterranean formations having a temperature of 65.degree. C. or higher, and a water hardness of 1000 ppm or higher.
In other flooding operations, rather than water, other fluids can be used. Some fluids which are used are carbon dioxide and steam. Because of the high temperature required in steam flooding or other steam stimulation methods, many of the gels used for blocking water are not suitable or satisfactory for blocking steam. Other steam treating methods such as "Push and Pull" operations, sometimes referred to aa "cyclic steam injection" or "Huff and Puff" operations, where a production well is steamed for several days and then produced for a month or so result in steam channels being formed which if not blocked will result in an inefficient steaming operation due to loss of steam into channels which drain into nonproductive parts of the reservoir. Again because many of the existing gels degrade rapidly at steam temperatures, polymers such as polyacrylamides are generally not satisfactory. Other fluids such as carbon dioxide can also be used in push and pull operations.
Flooding operations using carbon dioxide and other gases as the drive fluid frequently experience a loss of drive fluid to nonproductive parts of the reservoir because of greater ability of gases to dissipate into such channel as opposed to liquids. Loss of drive gases in flooding operations and steam in stimulation methods is more difficult to prevent because the flow channels responsible for such losses can be very small in diameter or width thereby making it very difficult to fill such channels with a blocking agent. Some viscous plugging substances, even though they may have the desired stability at higher temperatures, are not able to penetrate and effectively fill narrow channels, particularly as such channels become more distant from the wellbore.
Thus there is a need for plugging fluids which can be formulated to penetrate deeply into the formation. The use of this invention addresses this problem and provides polyvinyl alcohol based gels which can be tailor made to the particular problem at hand and which can overcome many of the shortcomings of prior art plugging agents and gels.
Polyvinyl alcohol gels have been used to protect well casings from corrosion. U.S. Pat. No. 2,832,414 discloses such a method wherein an aqueous solution of a water soluble polyvinyl alcohol which is capable of forming a gel if maintained in a quiescent state, is pumped into the annular space between the casing and the wall of the bore hole. After allowing the polymer to remain quiescent over a period of time a gel is formed. The thusly formed gel prevents the intrusion of formation water into the annular space thereby reducing corrosion of the metal casing. Apparently, no crosslinking agent is employed and for that reason is not believed that this particular gel would be useful for plugging channels or fractures on a permanent bases. Furthermore, in U.S. Pat. No. 2,832,414 the gel is used to fill a relatively large but stagnant cavity compared to the volume of a typical channel in a subterranean formation associated with hydrocarbon production from a wellbore.
Studies of the macroscopic changes in polyvinyl acetate gels that occur upon removal from swelling equilibrium with isopropyl alcohol were reported in the Journal of Colloid and Interface Science, Vol. 90, No. 1, November 1982, pages 34 to 43. These studies were conducted using films of gels having various degrees of crosslinking and polymer concentration. The polyvinyl acetate gels were formed from precursor polyvinyl alcohol gels that were crosslinked with glutaric dialdehyde which were then converted to acetate gels by polymer homologous acetylation.
U.S. Pat. No. 3,265,657 discloses a process for preparing an aqueous polyvinyl alcohol composition, which remains fluid for at least a few seconds after preparation and spontaneously gels thereafter. The gel is formed by contacting a gelable fluid aqueous polyvinyl alcohol solution with a hexavalent chromium compound and a reductive agent to convert CR(VI) to Cr(III). The compositions are used to produce foams suitable as insulating, acoustical, and packaging materials. The gels are crosslinked with chromium, not an aldehyde.
U.S. Pat. No. 3,658,745 discloses a hydrogel which is capable of significant expansion upon cooling in water and reversible shrinking upon heating which comprises a crosslinked acetalated hydrogel formed by reacting a polyvinyl alcohol previously dissolved in water and a monaldehyde and a dialdehyde. The hydrogels are alleged to have sufficient crosslinking to prevent imbibition of macromolecular materials such as proteins but not the imbibition of micromolecular materials such as low molecular weight water solutes. These hydrogels are alleged to be useful for dialytic purification when pure water is added to the macromolecular solution after each cycle. Apparently these particular hydrogels are able to absorb and desorb water and microsolutes with alternate cooling and heating cycles. Apparently a major amount of shrinkage of these gels occurs upon slight heating such as from 12.degree. to 37.degree. C. which indicates that these gels would have little value for blocking water in subterranean formations, especially at temperatures of 37.degree. C. or higher.